Insulation-liquid-filled electrical equipment, such as oil-filled shunt reactors, bushings, and especially transformers such as power and distribution transformers, are filled with insulation liquid, in particular oil, for cooling and electrical insulation purposes. Faults inside the electrical equipment as well as degradation of the insulation liquid and of other insulation components such as insulation paper provided within the electrical equipment can form decomposition gasses which mainly dissolve into the liquid. This is valid for equipment employing both mineral oil and oil from natural sources.
It is important to detect such faults, errors and degradations early, since especially transformers are important components of the electrical grid, and their failure can be very costly. Hence, a transformer is supposed to operate continuously and as error-free as possible over many years or even decades.
The quantity and composition of the decomposition gases is dependent on the underlying defect: A large fault with high energy content, such as rapid overheating or arcing, causes large amounts of gas to be produced in a short period of time, whereas the amount of gas produced by a small fault may be relatively smaller. Also, the relative concentrations of the different gasses dissolved might indicate the specific type of fault. Thus, if the nature and amount of individual gases dissolved in the insulation liquid are known, the occurrence of a change of the concentration of a specific gas in the oil can be used to identify an electrical fault in the equipment. It is known that one of the most important indicators for electrical failure in oil insulated transformers is the occurrence of hydrogen gas dissolved in the oil, which is for example produced at a faulty portion of an insulation of a winding of the transformer by thermal or electrical decomposition of the oil. For this reason, it is desirable that such errors, which may eventually cause complete failure of the transformer, can be detected as early as possible by identifying a rise in hydrogen concentration. This should ideally be possible at a stage when appropriate counter-measures may still be taken before serious and potentially costly malfunction occurs.
At a very early stage of such an electrical fault, only a very small amount of hydrogen gas may be produced, which dissolves in the oil and thus a concentration of dissolved hydrogen builds up in the oil over a longer period of time—whereby the hydrogen concentration in the oil may, at least during an early phase of the failure, even be below a threshold at which it can be detected with most known detection methods.
Most modern electrical transformers in power grids are still not equipped with on-line or real-time monitoring devices for such gasses. In order to control and evaluate the health of these transformers, an oil sample from the insulating oil bath is periodically taken and sent to qualified laboratories where the dissolved gases and other oil properties are measured. This monitoring method is time consuming, lacks continuity, has the risk of human error and is highly priced. Even if this costly method is carried out more frequently, there are several possible sources for error in the process, for example changes in the chemical and physical properties of the probe during the transport between the point in time when the probe is drawn, and the moment when the gas content is actually determined in a laboratory. Also, this method does not provide any information on where a fault occurred in the transformer. Thus, this method shall be of no further interest here, even though it is still widely used.
On the other hand, in online-methods the gas concentration in the insulation liquid is monitored directly and (quasi-)continuously. For this purpose, monitoring systems exist, sometimes built-in, for measuring hydrogen in transformer oil. These systems are based on different sensing techniques. They include, for example, semiconductor sensors, thermal-conductivity analyzers, pellistors, and fuel cell sensors, amongst others. These sensing techniques usually require a complicated gas separation system that adds complexity and cost to the sensor design and calibration. Thus, these devices are generally cumbersome and expensive. Additionally, some of these monitoring techniques suffer from cross-sensitivity towards other gases present in the oil, which additionally makes the results less reliable.
Therefore, even advanced transformers, i.e. those equipped with a dedicated on-line gas monitoring system, are often still additionally and periodically verified with expensive laboratory tests to reassure the accuracy of the on-line gas monitoring system. Therefore, a quantitative, reliable, cheap and continuous hydrogen detection system employing a sensor would be ideal for monitoring hydrogen concentration in the insulating oil in order to be able to detect faults at a stage as early as possible. This implies that a health status of the transformer can be monitored online or even from a remote location.
There have been proposals for such on-line hydrogen monitoring devices which include thin film based fiber optic sensors, wherein a sensing material changes its optical properties upon an exposure to hydrogen dissolved in the oil. One such system for detecting hydrogen gas is described as an optical switching device in WO 2007 049965 A1.
Another proposal is provided in “Optical fiber sensor for the continuous monitoring of hydrogen in oil” by T. Mak, R. J. Westerwaal, M. Slaman, H. Schreuders, A. W. van Vugt, M. Victoria, C. Boelsma, B. Dam, in: Sensors and Actuators B 190 (2014) 982-989. Thereby, the proposed optical sensors include a sensitive film comprising, for example, an alloy of Mg and Ti, capped with a Pd-containing layer.
However, such known configurations leave great room for improvement. Firstly, the sensitivity of some of these sensors has, which may even be intended, a switch-type characteristic in the temperature regimes of interest. That is, these optical sensors fundamentally change their optical properties, namely their reflectance, when a threshold value of the supervised hydrogen concentration in the oil is reached. This means that a hydrogen detection system with such a sensor can and will only indicate if a certain threshold concentration of hydrogen has been reached or not. It can thus typically not detect or indicate that a slow rise of the hydrogen concentration occurs over a longer time period such as hours, days or even months, which might, however, be regarded as an indication for a slowly developing fault. Thus, it does not indicate the actual hydrogen concentration in the transformer oil, but only that a threshold value for the gas concentration has been reached or exceeded.
Other optical sensors do exhibit a continuous change of their optical properties with growing hydrogen concentrations in the oil, however they lack sensitivity in certain temperature and hydrogen concentration regimes which would be desirable for enabling monitoring the hydrogen concentration at a broad range of possible operating conditions of transformers. For example, the hydrogen sensor as used by Mak et al. (2014) can measure hydrogen concentrations continuously from 5 ppm to 1,500 ppm, however only above an operating temperature of 80° C. of the sensor. This is, however, higher than the standard oil temperature in most transformer types. At lower operating temperatures, which are much more significant for standard transformer operation, the effective measurement ranges for hydrogen concentrations are much smaller (and the sensitivity lower) with the known technology, so that it is improvable for the detection of transformer faults. In addition, often these metal-hydride systems do not show a reproducible optical behavior upon hydrogen cycling as required, which results in an instable response of the sensor over time.
In view of the above and other factors, there is a need for the present invention.